Carbon dioxide, which falls into the category of acid gases is commonly found in natural gas steams at levels as high as 80%. In combination with water, it is highly corrosive and rapidly destroys pipelines and equipment unless it is partially removed or exotic and expensive construction materials are used. Carbon dioxide also reduces the heating value of a natural gas stream and wastes pipeline capacity. In liquid natural gas (LNG) plants, carbon dioxide must be removed to prevent freezing in the low temperature chillers. The treatment of natural gas for the removal of carbon dioxide typically requires the processing of large volumes of gas to produce a treated gas product with about 1 to 4 mol-% carbon dioxide. The carbon dioxide is removed from natural gas for reasons such as improving the heating value of the treated gas for pipeline transmission and, recovering the carbon dioxide from gases associated with oil field CO2 injection for enhanced oil production.
In some applications it is necessary to purify the natural gas to a much greater extent. In particular, in circumstances when pipelines are not available, natural gas can be shipped from distant sources in the form of liquefied natural gas (LNG). Since LNG occupies only a fraction ( 1/600) of the volume of natural gas, and takes up less space, it is more economical to transport across large distances and can be stored in larger quantities. Liquefied natural gas, or LNG, is natural gas in its liquid form. When natural gas is cooled to minus 161° C. (−259° F.), it becomes a clear, colorless, odorless liquid. LNG is neither corrosive nor toxic. Natural gas is primarily methane, with relatively low concentrations of other hydrocarbons, water, carbon dioxide, nitrogen, oxygen and some sulfur compounds. It is necessary to remove many of these impurities prior to the process of producing the LNG. During the process known as liquefaction, natural gas is cooled below its boiling point and most of these impurities are removed. The remaining natural gas product after liquefaction is primarily methane with only small amounts of other hydrocarbons present. LNG weighs less than half the weight of water so it will float if spilled on water.
“Natural gas” is a general term which is applied to mixtures of inert gases and light hydrocarbon components which are derived from natural gas wells or from gas associated with the production of oil. Typically, the quality of the natural gas, as produced, will vary according to the content and amount of inert gases and other impurities in the natural gas. These inert gases such as nitrogen, carbon dioxide, and helium will reduce the heating value of the natural gas. Because untreated natural gas is usually saturated with water, the presence of carbon dioxide in significant amounts may make the natural gas corrosive. Natural gas is usually conveyed from its source to the consumer in pipelines. As a result, very rigid guidelines have been established by the gas transmission industry to maintain a high quality, safe product. Typical specification for pipeline quality natural gas include: Nitrogen less than 4 mol-%, and carbon dioxide less than 4 mol-%. However, at a 4 mol-% level, there would still be 40,000 parts per million (ppm) carbon dioxide. While this level is considered acceptable for pipeline transport of natural gas, in the production of LNG, the goal is to reduce the level of carbon dioxide by about a factor of 1000 to below 50 ppm.
The most important aspect of any process for treating natural gas is economics. The most critical characteristics of a CO2 removal process are the energy requirements and the concentration level to which CO2 can be lowered in the exit gas. Natural gas is treated in very high volumes making even slight differences of 1-2% in the capital or operating cost of the treatment units very significant factors in the selection of process technology. Furthermore, because natural gas is a potentially dangerous and explosive fuel, especially in the large volumes present at a treatment plant, processes are sought which have high reliability, simplicity and safety.
Liquid absorption systems are commonly used for the removal of carbon dioxide from natural gas. A physical solvent such as a dimethylether of polyethylene glycol or chemical solvents such as alkanolamines or alkali metal salts may be used to wash out carbon dioxide. The carbon dioxide rich solvent is subsequently regenerated by stripping of the carbon dioxide with heat. These liquid adsorption systems typically achieve about 200 ppmv carbon dioxide levels. When lower levels are desired, they can be supplemented with a molecular sieve adsorbent bed to lower the carbon dioxide level below 50 ppmv. These liquid absorption systems are effective, but they are expensive and it is desirable to develop more cost efficient systems for purification of natural gas.
Membranes such as those disclosed in U.S. Pat. No. 4,230,463 to Henis et al. are effective for separating at least one gas component from a gaseous mixture by permeation where the membranes have a coating in occluding contact with a porous separation membrane. Membranes may be used in a single stage or integrated in multiple stages to preferentially separate the more permeable component. However, the membranes will pass a portion of the less permeable gases along with the preferentially separated gas thereby limiting recovery of the non-permeable gases and producing a low quality permeate reject stream. As a result of this limitation, single stages of membranes are often combined with additional membrane stages and the permeate is recycled with the feed to the first stage to improve the separation and reduce losses. However, the use of additional membrane stages combined with the added recompression costs to recompress the permeate stream and recycle it to the first membrane stage are significant as membranes do not provide any economy of scale with increases in gas capacity for the same separation. The cost of membrane technology is directly proportional to the area of the membrane employed. U.S. Pat. No. 4,130,403 to Cooley et al. is an example of the use of multiple stages of membrane separation to obtain a carbon dioxide-rich permeating gas. Membrane systems have been found effective for gas pipeline applications, but they do not lower the carbon dioxide level to the extent needed for LPG applications. Typically they lower the level of carbon dioxide to about 20,000 ppmv, while the desired level of carbon dioxide for LPG is below 50 ppmv.
Alternatively carbon dioxide can be rejected from a multiple component gas stream comprising methane and carbon dioxide in a pressure swing adsorption (PSA) system by recovering high purity methane product and rejecting the tail gas comprising carbon dioxide. However, the PSA process doesn't operate efficiently at the pressures at which the natural gas is available, requiring that all of the gas feed to the PSA unit be reduced to a lower adsorption pressure and all of the treated gas to be recompressed to the product gas pressure. Unfortunately, large amounts of regeneration gas are required to properly regenerate the adsorbent beds. The loss of the regeneration gas from the system is what makes a PSA system inefficient for this application.
U.S. Pat. No. 4,229,188 discloses a process which combines a PSA and a membrane system to produce a high purity product essentially of a single gas. High purity hydrogen is recovered from a feed gas mixture containing hydrogen by passing the feed gas mixture to a selective adsorption unit to initially separate the hydrogen gas. The low pressure tail gas from the PSA is further treated by a membrane system to recover additional quantity of hydrogen. Alternatively, and as taught in U.S. Pat. No. 4,398,926 and U.S. Pat. No. 4,701,187, the feed gas mixture may initially be separated in a membrane separation unit to provide bulk separation of hydrogen. The separated hydrogen may then be passed to a PSA unit to achieve high purity hydrogen gas at high recovery. In U.S. Pat. No. 4,701,187, the tail gas purge stream from the PSA adsorption unit is compressed and recycled with the feed gas mixture to the membrane unit to form an efficient system.
In U.S. Pat. No. 4,863,492 a gas permeable membrane is combined with a PSA unit to produce a mixed gas product having a preset, adjustably-controlled gas ratio and a high purity second gas component. The permeate stream from the gas permeable membrane is fed to the PSA unit and the tail gas from the PSA unit is compressed and blended with the non-permeate steam to form the mixed gas product.
Membranes have been combined with PSA units to improve the recovery of light components. For example, U.S. Pat. No. 4,238,204 to Perry relates to a selective adsorption process for the recovery of a light gas, especially hydrogen, from a feed gas mixture by using a membrane permeator unit selectively permeable to the light gas to recover a more concentrated light gas from a stream comprising the light gas. The light gas is used to regenerate a selective adsorber unit. The more concentrated light gas is utilized in the selective adsorber unit, either blended with the feed gas mixture, or as a purging gas to improve the recovery of the highly purified light gas product.
U.S. Pat. No. 4,398,926 to Doshi relates to a process for recovery of hydrogen from a gas stream containing hydrogen and impurities. The process achieves the bulk separation of hydrogen from the gas stream in a membrane unit and then separates the hydrogen from the impurities in a PSA unit to produce a purified hydrogen product and a waste gas stream. A high pressure gas stream having a hydrogen content of up to 90 mol-% is passed to a permeable membrane capable of selectively permeating hydrogen. The separated hydrogen is recovered at reduced pressure and passed to a PSA unit adapted for operation at the reduced pressure. The non-permeate comprising hydrogen from the permeable membrane is recovered essentially at the higher pressure of the gas stream. A portion of the non-permeate is throttled to a lower pressure with appropriate power recovery and is passed to the PSA unit as a co-feed gas. The co-feed gas contributes to the recovery of the purified hydrogen product and a reduction in the operating costs for the desired hydrogen separation and purification.
Membrane and pressure swing adsorption (PSA) processes are safe and simple systems to operate. As dry systems, membrane and PSA processes, are less susceptible to corrosion and other operating problems associated with wet, amine based carbon dioxide removal systems. However, multistage membrane systems require large amounts of compression for efficient operation, which can represent large capital and energy costs. On the other hand, PSA systems are relatively inefficient at high pressures typically encountered in natural gas treating processes.